Large volumes of natural gas (i.e., primarily methane) are located in remote areas of the world. This gas has significant value if it can be economically transported to market. Where the gas reserves are located in reasonable proximity to a market and the terrain between the two locations permits, the gas is typically produced and then transported to market through submerged and/or land-based pipelines. However, when gas is produced in locations where laying a pipeline is infeasible or economically prohibitive, other techniques must be used for getting this gas to market.
A commonly used technique for non-pipeline transport of gas involves liquefying the gas at or near the production site and then transporting the liquefied natural gas to market in specially-designed storage tanks aboard transport vessels. The natural gas is cooled and condensed to a liquid state to produce liquefied natural gas (“LNG”). LNG is typically, but not always, transported at substantially atmospheric pressure and at temperatures of about −162° C. (−260° F.), thereby significantly increasing the amount of gas which can be stored in a particular storage tank on a transport vessel. Once an LNG transport vessel reaches its destination, the LNG is typically off-loaded into other storage tanks from which the LNG can then be revaporized as needed and transported as a gas to end users through pipelines or the like. LNG has been an increasingly popular transportation method to supply major energy-consuming nations with natural gas.
Processing plants used to liquefy natural gas are typically built in stages as the supply of feed gas, i.e., natural gas, and the quantity of gas contracted for sale increase. One traditional method of building an LNG processing plant is to build up a plant site in several sequential increments, or parallel trains. Each stage of construction may consist of a separate, stand-alone train, which, in turn, is comprised of all the individual processing units or steps necessary to liquefy a stream of feed gas into LNG and send it on to storage. Each train may function as an independent production facility. Train size can depend heavily upon the extent of the resource, technology and equipment used within the train, and the available funds for investment in the project development. Generally, the compressors are driven by combusting a portion of the natural gas feed in a gas turbine engine to generate mechanical energy, which is transferred to the compressor by a shaft. However, so called all-electric LNG plants have been conceptually discussed. In all-electric LNG plants, the refrigeration compressors are driven by electric motors, powered by a central power plant within the all-electric LNG plant. The central power plant uses gas turbines to generate electricity for an internal electric grid that powers the electric compressors. A benefit of this approach is that the gas turbines are located in a centralized power plant improving ease of maintenance activities.
Typical base load LNG plants are built to liquefy gas from a dedicated reservoir or set of reservoirs. For example, a base load LNG plant may have a production capability of 1-5 megatons/year (MTA), selected to match the amount of natural gas available for feed and fuel. Since the intent is to run continuously at maximum capacity, little emphasis is placed on the turndown capability of the plant other than to ensure that there is a range of operability during startup or process upset. LNG plants are often limited by the ability of the compressor driver to turn down efficiently. Turn down capability of the gas treating units may be limited.
LNG production may also be used for storing natural gas. For example, LNG peak shaving plants can be designed to balance pipeline capacity by storing LNG in tanks until it is economic to gasify the LNG for pipeline distribution. They are similar in function to underground storage of natural gas. Peak shaving plants have stand-alone gas treating facilities and, although they do have the flexibility to operate over a range of turndown, have significantly lower liquefaction capacity than base load LNG plants. Peak shaving plants have throughput ranging in the 1-20 MMSCFD range. 20 MMSCFD is approximately equivalent to 0.15 MTA, which is about 6 times smaller than the lower range of LNG base load plant capacity (1 MTA or 128 MMSCFD). Peak shaving plants typically operate with one motor or gas turbine driven compressor.
Countries with natural gas reserves commonly use a portion of the gas for domestic power generation. In most cases, the natural gas is treated upstream of the power plants to remove contaminants, such as H2S, CO2, and water. The treating equipment can be sized to provide a treated gas stream flow rate that is sufficient to meet the expected peak demand of the power utility. However, the power demand on a domestic grid typically swings with the ambient temperature and the gas treating facilities may be under-utilized except during the peak demand seasons, such as during the hottest months when air conditioning demand is high.
Due to the increase in demand seen in recent years, increased emphasis has been placed on cost and schedule efficiency of new gas liquefaction projects in order to reduce the cost of the delivered gas. Large natural gas liquefaction projects expose the developers to substantial commercial risk due to the large initial capital costs ($5 billion or more) of these projects. Improvements in cost, design, and schedule efficiency can help mitigate the substantial commercial risk associated with large LNG development projects.